Rig task management

ABSTRACT

Systems and methods for performing subterranean operations include receiving a digital rig plan which comprises a sequence of at least a subset of available rig tasks for a rig, executing a rig task in the digital rig plan that involves a fluid, monitoring at least one parameter of the fluid during execution of the rig task, and continuing or stopping the rig task based on the monitoring of the at least one parameter of the fluid.

CROSS-REFERENCE TO RELATED APPLICATION(S)

This application claims priority under 35 U.S.C. § 119(e) to U.S.Provisional Application No. 63/266,163, entitled “RIG TASK MANAGEMENT,”by Scott BOONE, filed Dec. 29, 2021, which is assigned to the currentassignee hereof and incorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

The present invention relates, in general, to the field of drilling andprocessing of wells. More particularly, present embodiments relate to asystem and method for analyzing and scoring adherence of rig equipmentand personnel to perform activities according to a well plan or rigplan.

BACKGROUND

During well construction operations, activities on a rig can beorganized according to a well plan. The well plan can be converted to arig plan (i.e., rig specific well construction plan) for implementationon a specific rig. Deviations from the well plan or rig plan can causerig delays, increase well site operation costs, and cause other impactsto operations. Poorly performed well plan activities or rig plan taskson the rig can cause delays or even unplanned activities or tasks if theactivity or task is in a high priority path. Delays in identifying thepoor performance can exacerbate these impacts. Therefore, improvementsin rig activity monitoring and reporting are continually needed.

SUMMARY

A system of one or more computers can be configured to performparticular operations or actions by virtue of having software, firmware,hardware, or a combination of them installed on the system that inoperation causes or cause the system to perform the actions. One or morecomputer programs can be configured to perform particular operations oractions by virtue of including instructions that, when executed by thedata processing apparatus, cause the apparatus to perform the actions.One general method includes performing subterranean operations which mayinclude executing a rig task that involves a fluid contained in adigital rig plan, obtaining sensor data from one or more sensorsconfigured to monitor at least one parameter of the fluid associatedwith the rig task contained in the digital rig plan, and continuing orstopping the rig task based on the sensor data.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of present embodimentswill become better understood when the following detailed description isread with reference to the accompanying drawings in which likecharacters represent like parts throughout the drawings, wherein:

FIG. 1A is a representative simplified front view of a rig beingutilized for a subterranean operation, in accordance with certainembodiments.

FIG. 1B is a representative simplified view of a user using possiblewearable devices for user input or identification, in accordance withcertain embodiments.

FIG. 2 is a representative partial cross-sectional view of a rig beingutilized for a subterranean operation, in accordance with certainembodiments.

FIG. 3 is a representative flow diagram of a method of performing asubterranean operation, in accordance with certain embodiments.

FIG. 4A is a representative list of well activities for an exampledigital well plan, in accordance with certain embodiments.

FIG. 4B is a representative functional diagram that illustrates theconversion of well plan activities to rig plan tasks, in accordance withcertain embodiments.

FIG. 5 is a representative functional diagram that illustrates possibledatabases used by a rig controller to convert a digital well plan to adigital rig plan, in accordance with certain embodiments.

DETAILED DESCRIPTION

The following description in combination with the figures is provided toassist in understanding the teachings disclosed herein. The followingdiscussion will focus on specific implementations and embodiments of theteachings. This focus is provided to assist in describing the teachingsand should not be interpreted as a limitation on the scope orapplicability of the teachings.

As used herein, the terms “comprises,” “comprising,” “includes,”“including,” “has,” “having,” or any other variation thereof, areintended to cover a non-exclusive inclusion. For example, a process,method, article, or apparatus that comprises a list of features is notnecessarily limited only to those features but may include otherfeatures not expressly listed or inherent to such process, method,article, or apparatus. Further, unless expressly stated to the contrary,“or” refers to an inclusive-or and not to an exclusive-or. For example,a condition A or B is satisfied by any one of the following: A is true(or present) and B is false (or not present), A is false (or notpresent) and B is true (or present), and both A and B are true (orpresent).

The use of “a” or “an” is employed to describe elements and componentsdescribed herein. This is done merely for convenience and to give ageneral sense of the scope of the invention. This description should beread to include one or at least one and the singular also includes theplural, or vice versa, unless it is clear that it is meant otherwise.

The use of the word “about”, “approximately”, or “substantially” isintended to mean that a value of a parameter is close to a stated valueor position. However, minor differences may prevent the values orpositions from being exactly as stated. Thus, differences of up to fourpercent (4%) for the value are reasonable differences from the idealgoal of exactly as described. A significant difference can be when thedifference is greater than four percent (4%).

As used herein, “tubular” refers to an elongated cylindrical tube andcan include any of the tubulars manipulated around a rig, such astubular segments, tubular stands, tubulars, and tubular string, but notlimited to the tubulars shown in FIG. 1A. Therefore, in this disclosure,“tubular” is synonymous with “tubular segment,” “tubular stand,” and“tubular string,” as well as “pipe,” “pipe segment,” “pipe stand,” “pipestring,” “casing,” “casing segment,” or “casing string.”

FIG. 1A is a representative simplified front view of a rig 10 at a rigsite 11 being utilized for a subterranean operation (e.g., tripping inor out a tubular string to or from a wellbore), in accordance withcertain embodiments. The rig site 11 can include the rig 10 with its rigequipment, along with equipment and work areas that support the rig 10but are not necessarily on the rig 10. The rig 10 can include a platform12 with a rig floor 16 and a derrick 14 extending up from the rig floor16. The derrick 14 can provide support for hoisting the top drive 18 asneeded to manipulate tubulars. A catwalk 20 and V-door ramp 22 can beused to transfer horizontally stored tubular segments 50 to the rigfloor 16. A tubular segment 52 can be one of the horizontally storedtubular segments 50 that is being transferred to the rig floor 16 viathe catwalk 20. A pipe handler 30 with articulating arms 32, 34 can beused to grab the tubular segment 52 from the catwalk 20 and transfer thetubular segment 52 to the top drive 18, the vertical storage area 36,the wellbore 15, etc. However, it is not required that a pipe handler 30be used on the rig 10. The top drive 18 can transfer tubulars directlyto and directly from the catwalk 20 (e.g., using an elevator coupled tothe top drive).

The tubular string 58 can extend into the wellbore 15, with the wellbore15 extending through the surface 6, and optionally a rotating controldevice (RCD) or wellhead 66, and into the subterranean formation 8. Whentripping the tubular string 58 into the wellbore 15, tubulars 54 aresequentially added to the tubular string 58 to extend the length of thetubular string 58 into the earthen formation 8. FIG. 1A shows aland-based rig. However, it should be understood that the principles ofthis disclosure are equally applicable to off-shore rigs where“off-shore” refers to a rig with water between the rig floor and theearth surface 6.

When tripping the tubular string 58 out of the wellbore 15, tubulars 54are sequentially removed from the tubular string 58 to reduce the lengthof the tubular string 58 in the wellbore 15. The pipe handler 30 can beused to remove the tubulars 54 from an iron roughneck 38 or a top drive18 at a well center 24 and transfer the tubulars 54 to the catwalk 20,the vertical storage area 36, etc. The iron roughneck 38 can break athreaded connection between a tubular 54 being removed and the tubularstring 58. A spinner assembly 40 (or pipe handler 30) can engage a bodyof the tubular 54 to spin a pin end 57 of the tubular 54 out of athreaded box end 55 of the tubular string 58, thereby unthreading thetubular 54 from the tubular string 58.

When tripping the tubular string 58 into the wellbore 15, tubulars 54are sequentially added to the tubular string 58 to increase the lengthof the tubular string 58 in the wellbore 15. The pipe handler 30 can beused to deliver the tubulars 54 to a well center on the rig floor 16 ina vertical orientation and hand the tubulars 54 off to an iron roughneck38 or a top drive 18. The iron roughneck 38 can make a threadedconnection between the tubular 54 being added and the tubular string 58.A spinner assembly 40 or pipe handler 30 can engage a body of thetubular 54 to spin a pin end 57 of the tubular 54 into a threaded boxend 55 of the tubular string 58, thereby threading the tubular 54 intothe tubular string 58. The wrench assembly 42 can provide a desiredtorque to the threaded connection, thereby completing the connection.

While tripping a tubular string into or out of the wellbore 15 can be asignificant part of the operations performed by the rig, many other rigtasks are also needed to perform a well construction according to adigital well plan. For example, pumping mud at desired rates,maintaining downhole pressures (as in managed pressure drilling),maintaining, and controlling rig power systems, coordinating, andmanaging personnel on the rig during operations, performing pressuretests on sections of the wellbore 15, cementing a casing string in thewellbore, performing well logging operations, as well as many other rigtasks.

A rig controller 250 can be used to control the rig 10 operationsincluding controlling various rig equipment, such as the pipe handler30, the top drive 18, the iron roughneck 38, the vertical storage areaequipment, imaging systems, various other robots on the rig 10 (e.g., adrill floor robot), or rig power systems 26. The rig controller 250 cancontrol the rig equipment autonomously (e.g., without periodic operatorinteraction), semi-autonomously (e.g., with limited operator interactionsuch as initiating a subterranean operation, adjusting parameters duringthe operation, etc.), or manually (e.g., with the operator interactivelycontrolling the rig equipment via remote control interfaces to performthe subterranean operation). A score can be determined (e.g., by the rigcontroller 250) for personnel or rig equipment used in performing thesubterranean operation to indicate an adherence of the personnel or rigequipment to perform the subterranean operation according to the wellplan or rig plan. The scores for individuals can indicate proficiency ofthe individual to perform the needed tasks for the subterraneanoperation, or if the individual is performing the needed tasks on timeand in the right location, or can indicate a need for additional skillstraining for the individual. The scores for the rig equipment canindicate that the equipment is operating correctly or that the equipmentmay need maintenance or repair.

The rig controller 250 can include one or more processors with one ormore of the processors distributed about the rig 10, such as in anoperator’s control hut 13, in the pipe handler 30, in the iron roughneck38, in the vertical storage area 36, in the imaging systems, in variousother robots, in the top drive 18, at various locations on the rig floor16 or the derrick 14 or the platform 12, at a remote location off of therig 10, at downhole locations, etc. It should be understood that any ofthese processors can perform control or calculations locally or cancommunicate to a remotely located processor for performing the controlor calculations. Each of the processors can be communicatively coupledto a non-transitory memory, which can include instructions for therespective processor to read and execute to implement the desiredcontrol functions or other methods described in this disclosure. Theseprocessors can be coupled via a wired or wireless network. All datareceived and sent by the rig controller 250 is in a computer-readableformat and can be stored in and retrieved from the non-transitorymemory.

The rig controller 250 can collect data from various data sources aroundthe rig (e.g., sensors, user input, local rig reports, etc.) and fromremote data sources (e.g., suppliers, manufacturers, transporters,company men, remote rig reports, etc.) to monitor and facilitate theexecution of a digital well plan. A digital well plan is generallydesigned to be independent of a specific rig, whereas a digital rig planis a digital well plan that has been modified to incorporate thespecific equipment available on a specific rig to execute the well planon the specific rig, such as rig 10. Therefore, the rig controller 250can be configured to monitor and facilitate the execution of the digitalwell plan by monitoring and executing rig tasks in the digital rig plan.

Examples of local data sources are shown in FIG. 1A where an imagingsystem can include the rig controller 250 and imaging sensors 72positioned at desired locations around the rig and around the supportequipment/material areas, such as mud pumps (see FIG. 2 ), horizontalstorage area 56, power system 26, etc., to collect imagery of thedesired locations. Also, various sensors 74 can be positioned at variouslocations around the rig 10 and the support equipment/material areas tocollect information from the rig equipment (e.g., pipe handler 30,roughneck 38, top drive 18, vertical storage area 36, etc.) and supportequipment (e.g., crane 46, forklift 48, horizontal storage area 56,power system 26, etc.) to collect operational parameters of theequipment. Additional information can be collected from other datasources, such as reports and logs 28 (e.g., tour reports, daily progressreports, reports from remote locations, shipment logs, delivery logs,personnel logs, etc.).

These data sources can be aggregated by the rig controller 250 and usedto determine an estimated well activity of the rig and comparing it tothe digital well plan to determine the progress and performance of therig 10 in executing the digital well plan. The data collected from thedata sources during a first time interval can be compared to referencedata in a well activity database to determine the estimated wellactivity of the rig along with a confidence level that can indicate alevel of confidence that the estimated well activity is the actual wellactivity being performed by the rig. A low confidence level may indicatethat there is a low probability that the estimated well activity is theactual well activity being performed by the rig, and a high confidencelevel may indicate that there is a high probability that the estimatedwell activity is the actual well activity being performed by the rig.With the confidence level determined and the estimated well activitydetermined, the rig controller 250 can compare the estimated wellactivity to the expected well activity (which can be defined by thedigital well plan) and determine if the estimated well activity is theactual well activity being performed on the rig 10.

If the confidence level is below a predetermined threshold, then datacan be collected from the data sources during a second time interval andcompared to reference data in a well activity database to confirm thatthe estimated well activity of the rig is the actual well activity beingperformed by the rig. The second time interval can be adjusted, based onthe confidence level, to capture more or fewer data from the datasources. For example, if the confidence level is below a secondpredetermined threshold, then the second time interval can be increasedto capture a larger amount of data from the data sources, but if theconfidence level is above the second predetermined threshold, then thesecond time interval can be decreased to capture a smaller amount ofdata from the data sources. In either case, the second time interval canbe adjusted as needed to confirm that the estimated well activity is theactual well activity being performed on the rig 10.

The data sources can also include wearables 70 (e.g., a smartwristwatch, a smartphone, a tablet, a laptop, an identification badge, awearable transmitter, etc.) that can be worn by an individual 4 (or user4) to identify the individual 4, deliver instructions to the individual4, or receive inputs from the individual 4 via the wearable 70 to therig controller 250 (see FIG. 1B). Network connections (wired orwireless) to the wearables 70 can be used for communication between therig controller 250 and the wearables 70 for information transfer.

FIG. 2 is a representative partial cross-sectional view of a rig 10being used to drill a wellbore 15 in an earthen formation 8. FIG. 2shows a land-based rig, but the principles of this disclosure canequally apply to off-shore rigs, as well. The rig 10 can include a topdrive 18 with a traveling block 19 used to raise or lower the top drive18. A derrick 14 extending from the rig floor, can provide thestructural support of the rig equipment for performing subterraneanoperations (e.g., drilling, treating, completing, producing, testing,etc.). The rig can be used to extend a wellbore 15 through the earthenformation 8 by using a tubular string 58 having a Bottom Hole Assembly(BHA) 60 at its lower end. The BHA 60 can include a drill bit 68 andmultiple drill collars 62, with one or more of the drill collarsincluding instrumentation 64 for LWD and MWD operations. During drillingoperations, drilling mud can be pumped from the surface 6 into thetubular string 58 (e.g., via pumps 84 supplying mud to the top drive 18via standpipe 86) to cool and lubricate the drill bit 68 and totransport cuttings to the surface via an annulus 17 between the tubularstring 58 and the wellbore 15.

The returned mud can be directed to the mud pit 88 through the flow line81 and the shale shaker 80. A fluid treatment system 82 can injectadditives as desired to the mud to condition the mud appropriately forthe current well activities and possibly future well activities as themud is being pumped to the mud pit 88. The mud pump 84 can pull mud fromthe mud pit 88 and drive it to the top drive 18 via standpipe 86 tocontinue the circulation of the mud through the tubular string 58.

Sensors 74 and imaging sensors 72 can be distributed about the rig anddownhole to provide information on the environments in these areas aswell as operating conditions, health of equipment, well activity ofequipment, fluid properties, WOB, ROP, RPM of the drill string, RPM ofthe drill bit 68, etc.

The rig 10 may generally be used to perform subterranean operations in awellbore 15, such as the drilling of the wellbore 15, completion of thewellbore 15, and subsequently production of hydrocarbon fuels from thewellbore 15. In some embodiments, the rig 10 or the rig controller 250may receive a digital rig plan which comprises a sequence of at least asubset of available rig tasks for the rig 10. In some embodiments, therig 10 or the rig controller 250 may thereafter execute one or more rigtasks in the digital rig plan.

In implementing the rig tasks in the digital rig plan, the rig 10 or therig controller 250 may control rig 10 equipment in accordance with thedigital rig plan. The rig 10 equipment may include a top drive 18, afluid pump 84, a fluid treatment system 82, a shale shaker 80, other rig10 equipment, or any combination thereof. In some embodiments, the fluidpump 84 may be configured to pump drilling mud through the top drive 18and into the wellbore 15. In some embodiments, the fluid treatmentsystem 82, the shale shaker 80, or a combination thereof may beconfigured to treat the drilling mud returning from the wellbore 15prior to the drilling mud returning to a mud pit 88 configured to storethe drilling mud.

In some embodiments, one or more of the rig tasks in the digital rigplan may involve a fluid. In some embodiments, the rig task may comprisepumping a fluid, treating a fluid, or a combination thereof. In someembodiments, the fluid may comprise drilling mud. In some embodiments,the rig task may comprise pumping the drilling mud through the top drive18 and into the wellbore 15. In some embodiments, a rig task may alsoinclude the return of the drilling mud from the wellbore 15 to the mudpit 88. In some embodiments, the rig task may comprise treating thedrilling mud with a fluid treatment system, a shale shaker, or acombination thereof before returning to the mud pit 88 configured tostore the drilling mud. In some embodiments, the rig task may occurduring the drilling of the wellbore 15, tripping of tubular 54 into thewellbore 15, or one or more other rig operations utilized to execute thedigital rig plan 102.

In some embodiments, one or more of the rig tasks may comprisemonitoring at least one parameter of the fluid during the execution ofthe rig task. The monitoring of the at least one parameter of the fluidcan be accomplished via one or more sensors 74 disposed about the rig10. The one or more sensors 74 may be communicatively coupled to the rigcontroller 250. In some embodiments, the one or more sensors 74 maycomprise a fluid rheology sensor, a pressure sensor, a temperaturesensor, environmental sensors (e.g., barometric pressure, dew point,atmospheric pressure, humidity, etc.), or a combination thereof. Themonitoring of the at least one parameter of the fluid can beaccomplished via one or more sensors 74 configured to measure the atleast one parameter of the fluid at the fluid pump 84, at the top drive18, at the fluid treatment system 82, at the shale shaker 80, in the mudpit 88, in the wellbore 15, or a combination thereof. In certainembodiments, the at least one parameter of the fluid may comprise a flowrate of the fluid, a pressure of the fluid, a temperature of the fluid,a chemical composition of the fluid, a presence or lack of presence of aparticular chemical or substance in the fluid, a presence or lack ofpresence of solids in the fluid, a wellbore pressure, or a combinationthereof.

The monitoring of the one or more parameters of the fluid may be used tocontrol the rig task. The rig task can be continued or stopped based onthe monitoring of the at least one parameter of the fluid. In someembodiments, the rig task may continue in response to the at least oneparameter of the fluid not being at a desired or predetermined value.Accordingly, in some embodiments, continuing the rig task may compriseno change to the digital rig plan. In some embodiments, the rig task maybe drilling of a wellbore, cleaning of a wellbore, cementing a wellbore,completing a wellbore, controlling inflow of production fluid from awellbore, or a combination thereof.

In some embodiments, continuing the rig task may comprise adjusting oneor more operational parameters of the digital rig plan. In someembodiments, adjusting the one or more operational parameters of thedigital rig plan may be implemented automatically by the rig controller,manually by an operator of the rig controller (e.g., local or remoteoperators), interactively between the rig controller and the operator,or a combination thereof. In some embodiments, sensor data of the atleast one parameter of the fluid may be obtained for a first timeinterval and compared to the digital rig plan, which may prompt theadjusting of at least one or more operational parameters of the digitalrig plan. Thereafter, in some embodiments, sensor data of the at leastone parameter of the fluid may be obtained for a second time intervalafter the first time interval and compared to the digital rig plan toensure conformance with the digital rig plan.

It will be appreciated that the monitoring of the one or more parametersof the fluid or the adjustment of one or more operational parameters ofthe digital rig plan may be accomplished to change the operation of therig 10 or control parameters of the wellbore 15. The monitoring of theone or more parameters of the fluid or the adjustment of the one or moreoperational parameters of the digital rig plan may occur in real time tobring about changes in real time. Further, in some embodiments,adjustment of the one or more operational parameters of the digital rigplan may attempt to eliminate waste, reduce the power requirement of therig, conserve power utilized by the rig, or optimize the rig 10equipment. Accordingly, in some embodiments, the one or more operationalparameters of the digital rig plan may comprise a flow rate of thefluid, an operational pump capacity of the fluid pump, implementation ofa fluid treatment, or a combination thereof.

In some embodiments, the rig task may be stopped in response to the atleast one parameter of the fluid being at a desired or predeterminedvalue. In some embodiments, the rig task may be stopped in response tothe wellbore being “clean” or otherwise having minimal solids present inthe drilling mud. Additionally, in some embodiments, stopping the rigtask may comprise proceeding to a next rig task in the digital rig plan.In some embodiments, stopping the rig task or proceeding to the next rigtask may be implemented automatically by the rig controller. In someembodiments, stopping the rig task or proceeding to the next rig taskmay be implemented manually by an operator (e.g., local or remote) ofthe rig controller.

FIG. 3 is a representative flow diagram of a method 300 of performing asubterranean operation, in accordance with certain embodiments. Themethod 300 may begin at block 302 with operations of receiving at therig controller 250 a digital rig plan 102 which comprises a sequence ofat least a subset of available rig tasks for a rig 10. Operations atblock 304 may include executing a rig task in the digital rig plan 102that involves a fluid. Operations at block 306 may include monitoring atleast one parameter of the fluid during the execution of the rig task.Operations at block 308 may include comparing the at least one parameterof the fluid to an expected parameter. Operations at block 310 mayinclude determining whether or not the rig task should be stopped orcontinued based on the comparing of the at least one parameter of thefluid. In certain embodiments, the method 300 may comprise operations ofcontinuing the rig task in response to the at least one parameter of thefluid not being at a desired or predetermined value (e.g., returning toblock 304 from block 310). In certain embodiments, the rig task can bestopped temporarily to adjust the at least one parameter of the fluid tothe expected parameter value (such as indicated in block 312), or themethod 300 may comprise stopping the rig task in response to the atleast one parameter of the fluid being at a desired or predeterminedvalue and proceeding to a next rig task in the digital rig plan (such asindicated in block 314) in response to the at least one parameter of thefluid being at a desired or predetermined value.

In a non-limiting embodiment, the method 300 can include monitoring, viaone or more sensors, one or more parameters of the fluid, determiningactual values of the one or more parameters, and comparing the actualvalues to expected values included in the digital rig plan 102. If theactual values are substantially equal to the expected values, the rigcontroller 250 can proceed with executing additional tasks of thedigital rig plan. However, if the actual values are not substantiallyequal to the expected values, then one or more of the following can beperformed: 1) the current task can be stopped until the actual valuesare substantially equal to the expected values, 2) the digital rig plan102 can be modified to manage the deviation from the digital rig plan102 and return the rig operations to the desired rig operations of theunmodified portion of the digital rig plan 102 to get back on trackregarding execution of the digital rig plan 102.

If the fluid is being pumped into the wellbore 15 via the tubular string58 with one or more sensors monitoring one or more fluid parameters ofthe fluid being pumped into the tubular string 58 and an actual valuedoes not substantially equal the expected value from the digital rigplan 102, then this may be an indication that the fluid is not beingmaintained properly.

In a non-limiting example, if the actual value of the weight of thefluid is detected to be 10.5 pounds per gallon (ppg), but the digitalrig plan 102 indicates that the weight of the fluid should be 11 ppg,then the rig task being performed may need to be stopped until theweight of the fluid is adjusted until it is substantially equal to theexpected value of 11 ppg. The rig task can be restarted when the weightof the fluid is substantially equal to the expected value. If thedetected fluid parameters indicate possibly serious events, then thedigital rig plan 102 can be modified to change or add rig tasks tomitigate the events. Modifying the digital rig plan 102 can be performedto mitigate the event and return the rig operations back to the originaldigital rig plan 102 tasks and continue executing the digital rig plan102.

The one or more sensors can detect an actual value for one or moreparameters of the fluid and compare the actual value to an expectedvalue, wherein the one or more parameters can be at least one of a mudweight of the fluid, a pressure of the fluid in the wellbore, aviscosity of the fluid, a concentration of a treatment in the fluid, atemperature of the fluid, or a combination thereof.

If the fluid is being received from the wellbore 15 with one or moresensors monitoring one or more fluid parameters of the fluid beingreceived from the wellbore 15 and an actual value does not substantiallyequal the expected value from the digital rig plan 102, this mayindicate that an event has already occurred, is currently occurring, orwill occur in the future (e.g., near future).

In a non-limiting example, if the actual value fails the comparison withthe expected value when one of the fluid parameters is pressure. Theactual value of the pressure can indicate an elevated pressure or apressure drop, which can indicate that the tubular string 58 haspenetrated an earth formation with more or less pressure than expected.An elevated pressure can indicate a kick or gas influx into the wellbore15. An elevated pressure can indicate that cuttings are restricting thecirculation of the fluid through the wellbore 15. A pressure drop canindicate a fluid loss in the wellbore 15. The digital rig plan 102 canbe modified to mitigate the unexpected pressure and begin executing themodified rig plan 102. The digital rig plan 102 can be modified todetermine the cause of the unexpected pressure, determine rig tasks orrig task modifications to mitigate the event and begin executing themodified rig plan 102.

In a non-limiting example, one or more sensors can indicate that a fluidlevel is not being properly maintained when tripping a tubular string 58out of the wellbore 15. The digital rig plan 102 can be modified todetermine the cause of the unexpected fluid level in the wellbore,determine rig tasks or rig task modifications to mitigate the event andbegin executing the modified rig plan 102. The digital rig plan 102 canbe modified to determine the cause of the unexpected fluid level,determine rig tasks or rig task modifications to mitigate the event andbegin executing the modified rig plan 102.

FIG. 4A is a representative list of well plan activities 170 for anexample digital well plan 100. This list of well plan activities 170 canrepresent the activities needed to execute a full digital well plan 100.However, in FIG. 4A the list of activities 170 is merely representativeof a subset of a complete list of activities needed to execute a fulldigital well plan 100 to drill and complete a wellbore 15 to a targetdepth (TD). The digital well plan 100 can include well plan activities170 with corresponding wellbore depths 172. However, these activities170 are not required for the digital well plan 100. More or feweractivities 170 can be included in the digital well plan 100 in keepingwith the principles of this disclosure. Therefore, the followingdiscussion relating to the well plan activities 170 is merely an exampleto illustrate the concepts of this disclosure.

After the rig 10 has been utilized to drill the wellbore 15 to a depthof 75, at activity 112, a Prespud meeting can be held to brief all rigpersonnel on the goals of the digital well plan 100. At activity 114,the appropriate personnel and rig equipment can be used to make-up (M/U)5 ½″ drill pipe (DP) stands in prep for the upcoming drilling operation.This can, for example, require a pipe handler, horizontal or verticalstorage areas for tubular segments, or tubular stands.

At activity 118, the appropriate personnel and rig equipment can be usedto pick up (P/up), makeup (M/up), and run-in hole (RIH) a BHA with a 36″drill bit 68. This can, for example, require BHA components; a pipehandler to assist in the assembly of the BHA components; a pipe handlerto deliver BHA to a top drive; and lowering the top drive to run the BHAinto the wellbore 15.

At activity 120, the appropriate personnel and rig equipment can be usedto drill 36″ hole to a TD of the section, such as 652 ft, to +/- 30 ftinside a known formation layer (e.g., Dammam), and perform a deviationsurvey at depths of 150′, 500′ and TD (i.e., 652′ in this example). Atactivity 122, the appropriate personnel and rig equipment can be used topump a high-viscosity pill through the wellbore 15 via the tubularstring 58 and then circulate wellbore 15 clean. At activity 124, theappropriate personnel and rig equipment can be used to perform a “wipertrip” by pulling the tubular string 58 out of the hole (Pull out ofhole - POOH) to the surface 6; clean stabilizers on the tubular string58; and run the tubular string 58 back into the hole (Run in hole -RIH)to the bottom of the wellbore 15.

At activities 126 thru 168, the appropriate personnel and rig equipmentcan be used to perform the indicated well plan activities. Wellactivities can include the personnel, equipment, or materials needed todirectly execute the well plan activities using the specific rig 10, andthose activities that ensure the personnel, equipment, or materials areavailable and configured to support the primary activities.

FIG. 4B is a functional diagram that can illustrate the conversion ofwell plan activities 170 to rig plan tasks 190 of a rig specific digitalrig plan 102. When a well plan 100 is designed, well plan activities 170can be included to describe primary activities needed to construct adesired wellbore 15 to a TD. However, the well plan 100 activities 170are not specific to a particular rig, such as rig 10. It may not beappropriate to use the well plan activities 170 to direct specificoperations on a specific rig, such as rig 10. Therefore, a conversion ofthe well plan activities 170 can be performed to create a list of rigplan tasks 190 of a digital rig plan 102 to construct the desiredwellbore 15 using a specific rig, such as rig 10. This conversion engine180 (which can run on a computing system such as the rig controller 250)can take the non-rig specific well plan activities 170 as an input andconvert each of the non-rig specific well plan activities 170 to one ormore rig specific tasks 190 to create a digital rig plan 102 that can beused to direct tasks on a specific rig, such as rig 10, to construct thedesired wellbore 15.

As a way of example, a high-level description of the conversion engine180 will be described for a subset of well plan activities 170 todemonstrate a conversion process to create the digital rig plan 102. Thewell plan activity 118 states, in abbreviated form, to pick up, make up,and run-in hole a BHA 60 with a 36″ drill bit. The conversion engine 180can convert this single non-rig specific activity 118 into, for example,three rig-specific tasks 118.1, 118.2, 118.3. Task 118.1 can instructthe rig operators or rig controller 250 to pick up the BHA 60 (which hasbeen outfitted with a 36″ drill bit) with a pipe handler. At task 118.2,the pipe handler can carry the BHA 60 and deliver it to the top drive18, with the top drive 18 using an elevator 44 to grasp and lift the BHA60 into a vertical position. At task 118.3, the top drive 18 can lowerthe BHA 60 into the wellbore 15 which has already been drilled to adepth of 75′ for this example. The top drive 18 can lower the BHA 60 tothe bottom of the wellbore 15 to have the drill bit 68 in position tobegin drilling as indicated in the following well activity 120.

The well plan activity 120 states, in abbreviated form, to drill a 36″hole to a target depth (TD) of the section, such as 652 ft, to +/- 30 ftinside a known formation layer (e.g., Dammam), and performing adeviation survey at depths of 150′, 500′ and TD (i.e., 652′ in thisexample). The conversion engine 180 can convert this single non-rigspecific activity 120 into, for example, seven rig-specific tasks 120.1to 120.7. Task 120.1 can instruct the rig operators or rig controller250 to circulate mud through the top drive 18, through the tubularstring 58, through the BHA 60, and exiting the tubular string 58 throughthe drill bit 68 into the annulus 17. For this example, the mud flowrequires two mud pumps 84 to operate at “NN” strokes per minute, where“NN” is a desired value that delivers the desired mud flow and pressure.At task 120.2, the shaker tables can be turned on in preparation forcuttings that should be coming out of the annulus 17 when the drillingbegins. At task 120.3, a mud engineer can verify that the mudcharacteristics are appropriate for the current tasks of drilling thewellbore 15. If the rheology indicates that mud characteristics shouldbe adjusted, then additives can be added to adjust the mudcharacteristics as needed.

At task 120.4, rotary drilling can begin by lowering the drill bit intocontact with the bottom of the wellbore 15 and rotating the drill bit byrotating the top drive 18 (e.g., rotary drilling). The drillingparameters can be set to be “XX” ft/min for the rate of penetration(ROP), “YY” lbs. for weight on bit (WOB), and “ZZ” revolutions perminute (RPM) of the drill bit 68.

At task 120.5, as the wellbore 15 is extended by the rotary drillingwhen the top end of the tubular string 58 is less than “XX” ft above therig floor 16, then a new tubular segment (e.g., tubular, tubular stand,etc.) can be added to the tubular string 58 by retrieving a tubularsegment 50, 54 from tubular storage via a pipe handler, stop mud flowand disconnect the top drive from the tubular string 58, hold thetubular string 58 in place via the slips at well center, raise the topdrive 18 to provide clearance for the tubular segment to be added,transfer tubular segment 50, 54 from the pipe handler 30 to the topdrive 18, connect the tubular segment 50, 54 to the top drive 18, lowerthe tubular segment 50, 54 to the stump of the tubular string 58 andconnect it to the tubular string 58 using a roughneck to torque theconnection, then start mud flow. This can be performed each time the topend of the tubular string 58 is lowered below “XX” ft above the rigfloor 16.

At task 120.6, add tubular segments 50, 54 to the tubular string 58 asneeded in task 120.5 to drill wellbore 15 to a depth of 150 ft. Stoprotation of the drill bit 68 and stop mud pumps 84.

At task 120.7, perform a deviation survey by reading the inclinationdata from the BHA 60, comparing the inclination data to expectedinclination data, and report deviations from the expected. Correctdrilling parameters if deviations are greater than a pre-determinedlimit.

The conversion from a well plan 100 to a rig-specific rig plan 102 canbe performed manually or automatically with the best practices andequipment recipes known for the rig that is to be used in the wellboreconstruction.

FIG. 5 is a representative functional block diagram of the rig planengine 180 that can include possible databases used by a rig controller250 to convert a digital well plan 100 to a digital rig plan 102 and foridentifying individuals detected in work zones on the rig 10. The rigplan engine 180 can be a program (i.e., list of instructions 268) thatcan be stored in the non-transitory memory 252 and executed byprocessor(s) 254 of the rig controller 250 to convert a digital wellplan 100 to a digital rig plan 102 or identify individuals 4 on the rig10.

A digital well plan 100 can be received at an input to the rigcontroller 250 via a network interface 256. The digital well plan 100can be received by the processor(s) 254 and stored in the memory 252.The processor(s) 254 can then begin reading the sequential list of wellplan activities 170 of the digital well plan 100 from the memory 252.The processor(s) 254 can process each well plan activity 170 to createrig-specific tasks to implement the respective activity 170 on aspecific rig (e.g., rig 10).

To convert each well plan activity 170 to rig-specific tasks for a rig10, processor(s) 254 must determine the equipment available on the rig10, the best practices, operations, and parameters for running eachpiece of equipment, and the operations to be run on the rig to implementeach of the well plan activities 170.

Referring again to FIG. 5 , the processor(s) 254 are communicativelycoupled to the non-transitory memory 252 which can store multipledatabases for converting the well plan 100 into the rig plan 102. A rigoperations database 260 includes rig operations for implementing each ofthe well plan activities 170. Each of the rig operations can include oneor more tasks to perform the rig operation. The processor(s) 254 canretrieve those operations for implementing the first rig activity 170from the rig operations database 260 including the task lists for eachoperation. The processor(s) 254 can receive a rig type RT from a userinput or the network interface 256. With the rig type RT, theprocessor(s) 254 can retrieve a list of equipment available on the rig10 from the rig type database 262, which can contain equipment lists fora plurality of rig types. The available equipment can be determined fromthe rig equipment database 264.

The processor(s) 254 can then convert the operational tasks to rigspecific tasks to implement the operations on the rig 10. The rigspecific tasks can include the appropriate equipment for rig 10 toperform the operation task. The processor(s) 254 can then collect therecipes for operating each of the available equipment for rig 10 fromthe recipes database 266, where the recipes can include best practiceson operating the equipment, preferred parameters for operating theequipment, and operational tasks for the equipment (such as turn ONprocedures, ramp up procedures, ramp down procedures, shutdownprocedures, etc.). A full set of available rig tasks can be stored inthe rig tasks database 267. A full set of available well activities canbe stored in the well activities database 258. Parameters for all rigequipment, including best practices for the rig equipment can be storedin the parameters database 276.

Therefore, the processor(s) 254 can retrieve each of the well planactivities 170 and convert them to a list of rig specific tasks that canperform the respective well plan activity 170 on the rig 10. Afterconverting all of the well plan activities 170 to rig specific tasks 190and creating a sequential list of the tasks 190, the processor(s) 254can store the resulting digital rig plan 102 in the memory 252. When therig 10 is operational and positioned at the proper location to drill awellbore 15, the rig controller 250, via the processor(s) 254, can beginexecuting the list of tasks in the digital rig plan 102 by sendingcontrol signals and messages to the equipment control 270.

The rig controller 250 can also receive user input from an input device272 or display information to a user or individual 4 via a display 274.The input device 272 in cooperation with the display 274 can be used toinput well plan activities, initiate processes (such as converting thedigital well plan 100 to the digital rig plan 102), select alternativeactivities, or rig tasks during the execution of digital well plan 100or digital rig plan 102, or monitor operations during well planexecution. The input device 272 can also include the sensors 74 and theimaging sensors 72, which can provide sensor data (e.g., image data,temperature sensor data, pressure sensor data, operational parametersensor data, etc.) to the rig controller 250 for determining the actualwell activity of the rig.

VARIOUS EMBODIMENTS

Embodiments of a rig 10, a rig controller 250, a method 300, or othermethods disclosed herein may include one or more of the following:

Embodiment 1. A method of performing a subterranean operation,comprising: receiving a digital rig plan which comprises a sequence ofat least a subset of available rig tasks for a rig; executing a rig taskin the digital rig plan that involves a fluid; monitoring at least oneparameter of the fluid during the execution of the rig task; andcontinuing or stopping the rig task based on the monitoring of the atleast one parameter of the fluid.

Embodiment 2. The method of embodiment 1, wherein the digital rig planis received into a rig controller.

Embodiment 3. The method of embodiment 2, wherein the rig controller isconfigured to control rig equipment in accordance with the digital rigplan.

Embodiment 4. The method of embodiment 3, wherein the rig equipmentcomprises a top drive, a fluid pump, a fluid treatment system, a shaleshaker, or a combination thereof.

Embodiment 5. The method of embodiment 4, wherein the fluid pump isconfigured to pump drilling mud from the rig, through a tubular string,and into a wellbore.

Embodiment 6. The method of embodiment 5, wherein the fluid treatmentsystem, the shale shaker, or a combination thereof are configured totreat the drilling mud returning from the wellbore prior to the drillingmud returning to a mud pit configured to store the drilling mud.

Embodiment 7. The method of any one of embodiments 1 to 6, wherein therig task comprises pumping a fluid, treating a fluid, or a combinationthereof.

Embodiment 8. The method of embodiment 7, wherein the fluid comprisesdrilling mud.

Embodiment 9. The method of embodiment 8, wherein the rig task comprisespumping the drilling mud from the rig, through a tubular string, andinto the wellbore.

Embodiment 10. The method of any one of embodiments 8 to 9, wherein therig task comprises treating the drilling mud with a fluid treatmentsystem, a shale shaker, or a combination thereof.

Embodiment 11. The method of any one of embodiments 7 to 10, wherein therig task occurs during drilling of the wellbore, tripping of tubularinto the wellbore, or a combination thereof.

Embodiment 12. The method of any one of embodiments 1 to 11, wherein themonitoring of the at least one parameter of the fluid is accomplishedvia one or more sensors.

Embodiment 13. The method of embodiment 12, wherein the one or moresensors are communicatively coupled to a rig controller.

Embodiment 14. The method of any one of embodiments 12 to 13, whereinthe one or more sensors comprise a fluid rheology sensor, a pressuresensor, a temperature sensor, or a combination thereof.

Embodiment 15. The method of any one of embodiments 12 to 14, whereinthe monitoring of the at least one parameter of the fluid isaccomplished via one or more sensors configured to measure the at leastone parameter of the fluid at the fluid pump, at the top drive, at thefluid treatment system, at the shale shaker, in the mud pit, in thewellbore, or a combination thereof.

Embodiment 16. The method of any one of embodiments 1 to 15, wherein theat least parameter of the fluid comprises a flow rate of the fluid, apressure of the fluid, a temperature of the fluid, a chemicalcomposition of the fluid, a presence or lack of presence of a particularchemical or substance in the fluid, a presence or lack of presence ofsolids in the fluid, a wellbore pressure, or a combination thereof.

Embodiment 17. The method of any one of embodiments 1 to 16, wherein thecontinuing the rig task occurs in response to the at least one parameterof the fluid not being at a desired or predetermined value.

Embodiment 18. The method of any one of embodiments 1 to 17, wherein thecontinuing the rig task comprises no change to the digital rig plan.

Embodiment 19. The method of any one of embodiments 1 to 17, wherein thecontinuing the rig task comprises adjusting one or more operationalparameters of the digital rig plan.

Embodiment 20. The method of embodiment 19, wherein the adjusting theone or more operational parameters of the digital rig plan isimplemented automatically by the rig controller, manually by an operatorof the rig controller, interactively between the rig controller and theoperator, or a combination thereof.

Embodiment 21. The method of any one of embodiments 1 to 20, wherein theone or more adjusted operational parameters of the digital rig plancomprises a flow rate of the fluid, an operational pump capacity of thefluid pump, a number of fluid pumps employed, implementation of a fluidtreatment, or a combination thereof.

Embodiment 22. The method of any one of embodiments 1 to 21, wherein thestopping the rig task occurs in response to the at least one parameterof the fluid being at a desired or predetermined value.

Embodiment 23. The method of embodiment 22, wherein the stopping the rigtask comprises proceeding to a next rig task in the digital rig plan.

Embodiment 24. The method of any one of embodiments 22 to 23, whereinthe stopping the rig task is implemented automatically by the rigcontroller, manually by an operator of the rig controller, interactivelybetween the rig controller and the operator, or a combination thereof.

Embodiment 25. A system for performing a subterranean operation,comprising: a rig controller configured to receive a digital rig planand implement the steps of any one of embodiments 1 to 24.

Embodiment 26. A method of performing a subterranean operation,comprising:

-   receiving a digital rig plan which comprises a sequence of at least    a subset of available rig tasks for a rig;-   executing a rig task in the digital rig plan that involves a fluid;-   monitoring at least one parameter of the fluid during execution of    the rig task; and-   adjusting the digital rig plan based on the monitoring of the at    least one parameter of the fluid.

Embodiment 27. The method of embodiment 26, further comprising:

comparing an actual value of the at least one parameter of the fluid toan expected value in the digital rig plan.

Embodiment 28. The method of embodiment 27, further comprising:

adjusting the fluid to cause the actual value of the at least oneparameter to substantially equal the expected value.

Embodiment 29. The method of embodiment 28, further comprising:

-   stopping the rig task until the actual value substantially equals    the expected value; and-   resuming the rig task after the actual value substantially equals    the expected value.

Embodiment 30. The method of embodiment 29, wherein the fluid is beingpumped into a tubular string in a wellbore, wherein the at least oneparameter is at least one of:

-   a mud weight of the fluid;-   a pressure of the fluid in the wellbore;-   a viscosity of the fluid;-   a concentration of a treatment in the fluid; and-   a combination thereof.

Embodiment 31. The method of embodiment 27, wherein the comparing of theactual value with the expected value indicates that an event in awellbore has occurred, is occurring, or will occur.

Embodiment 32. The method of embodiment 31, wherein the event is atleast one of:

-   an unexpected spike in pressure in the wellbore;-   an unexpected drop in the pressure in the wellbore;-   a build-up of cuttings is restricting circulation of the fluid;-   gas influx into the wellbore;-   gas present in the cuttings;-   fluid loss into the wellbore;-   low fluid level in the wellbore; and-   a combination thereof.

Embodiment 33. The method of embodiment 31, further comprising:

adjusting the digital rig plan to manage the event, via adjusting one ormore rig tasks, adding one or more rig tasks, or combinations thereof.

Embodiment 34. A system for performing a subterranean operation,comprising:

a rig controller configured to receive a digital rig plan and implementthe method of any one of embodiments 25 to 33.

While the present disclosure may be susceptible to various modificationsand alternative forms, specific embodiments have been shown by way ofexample in the drawings and tables and have been described in detailherein. However, it should be understood that the embodiments are notintended to be limited to the particular forms disclosed. Rather, thedisclosure is to cover all modifications, equivalents, and alternativesfalling within the spirit and scope of the disclosure as defined by thefollowing appended claims. Further, although individual embodiments arediscussed herein, the disclosure is intended to cover all combinationsof these embodiments.

1. A method of performing a subterranean operation, comprising:receiving a digital rig plan, at a rig controller, which comprises asequence of at least a subset of available rig tasks for a rig;executing, via the rig controller, a rig task in the digital rig planthat involves a fluid; monitoring, via one or more sensors, at least oneparameter of the fluid during execution of the rig task; and continuingor stopping the rig task based on the monitoring of the at least oneparameter of the fluid.
 2. The method of claim 1, wherein the one ormore sensors are communicatively coupled to the rig controller.
 3. Themethod of claim 1, wherein the one or more sensors comprise a fluidrheology sensor, a pressure sensor, a temperature sensor, anenvironmental sensor, or a combination thereof.
 4. The method of claim1, wherein the at least one parameter of the fluid comprises a flow rateof the fluid, a pressure of the fluid, a temperature of the fluid, achemical composition of the fluid, a presence or lack of presence of aparticular chemical or substance in the fluid, a presence or lack ofpresence of solids in the fluid, a wellbore pressure, or a combinationthereof.
 5. The method of claim 1, wherein continuing the rig taskoccurs in response to the at least one parameter of the fluid not beingat a predetermined value.
 6. The method of claim 1, wherein continuingthe rig task comprises no change to the digital rig plan.
 7. The methodof claim 1, wherein continuing the rig task comprises adjusting one ormore operational parameters of the digital rig plan.
 8. The method ofclaim 1, wherein the digital rig plan is modified to create a modifiedrig plan based on the monitoring of the at least one parameter of thefluid, and wherein the continuing the rig task comprises proceeding withexecution of the modified rig plan.
 9. The method of claim 1, whereinthe stopping the rig task occurs in response to the at least oneparameter of the fluid being at a predetermined value.
 10. The method ofclaim 9, wherein the stopping the rig task causes the rig controller toproceed to executing a next rig task in the digital rig plan.
 11. Themethod of claim 1, wherein the stopping the rig task is implementedautomatically by the rig controller, implemented manually by an operatorof the rig controller, implemented interactively between the rigcontroller and the operator, or a combination thereof.
 12. A method ofperforming a subterranean operation, comprising: receiving a digital rigplan which comprises a sequence of at least a subset of available rigtasks for a rig; executing a rig task in the digital rig plan thatinvolves a fluid; monitoring at least one parameter of the fluid duringexecution of the rig task; and adjusting the digital rig plan based onthe monitoring of the at least one parameter of the fluid.
 13. Themethod of claim 12, further comprising: comparing an actual value of theat least one parameter of the fluid to an expected value in the digitalrig plan.
 14. The method of claim 13, further comprising: adjusting thefluid to cause the actual value of the at least one parameter tosubstantially equal the expected value.
 15. The method of claim 14,further comprising: stopping the rig task until the actual valuesubstantially equals the expected value; and resuming the rig task afterthe actual value substantially equals the expected value.
 16. The methodof claim 15, wherein the fluid is being pumped into a tubular string ina wellbore, wherein the at least one parameter is at least one of: a mudweight of the fluid; a pressure of the fluid in the wellbore; aviscosity of the fluid; a concentration of a treatment in the fluid; anda combination thereof.
 17. The method of claim 13, wherein the comparingof the actual value with the expected value indicates that an event in awellbore has occurred, is occurring, or will occur.
 18. The method ofclaim 17, wherein the event is at least one of: a spike in pressure inthe wellbore; a drop in the pressure in the wellbore; a build-up ofcuttings; gas influx into the wellbore; gas present in the cuttings;fluid loss into the wellbore; low fluid level in the wellbore; and acombination thereof.
 19. The method of claim 17, further comprising:creating a modified digital rig plan by adjusting the digital rig planto manage the event, via adjusting one or more rig tasks, adding one ormore rig tasks, deleting one or more rig tasks, or combinations thereof.20. The method of claim 19, further comprising: executing the modifieddigital rig plan to manage the event.